Recalculating. . .plant value/cost in the transition to grid support

If you don’t know what the “duck curve” is, you must have retired from the power industry five years ago. Simply put, it is what higher and higher penetration of renewable energy looks likes to a grid operator, who begins to have nightmares about the rising slope of the two daily ramps shown in the linked document.

Fig 1 is what the duck curve “looks” like to a combined-cycle (CC) plant filling in around the renewable capacity. Operating hours go down, starts go up, and equivalent availability suffers.

Grid support Fig 1

Jesse Murray, NV Energy’s director of renewable programs, suggests many CCs will see such “transitions” as more utility and distributed solar and other forms of distributed generation (DG) come online. “Competition at the wholesale level is well understood,” Murray notes, “but competition at the retail level may not be.” Until that gap closes, CCs are well-suited to fill in around renewables and retail DG because of their flexibility and relatively low operating costs.

DG units can have benefits for, but also impacts on, the grid, Murray notes. Either way, each DG device enjoys the luxury of using the grid for “virtual storage” of electricity, a benefit that isn’t always recognized or understood. For example, he says, a rooftop solar PV unit typically is not sized for when large appliances start up. But the stress of the in-rush of current and voltage, or spike, isn’t felt by the homeowner because he/she is interconnected to a healthy, reliable grid.

Nevada is aggressively replacing thermal generating resources with solar energy, though unlike its giant neighbor to the west, the transition is proceeding more “organically,” not through costly mandates. The bottom line: NV Energy has approximately 400 MW of utility-scale solar energy in production with nearly that much in construction and DG fractions. The utility provides net metering support to 20,000 solar PV and other DG customers currently, with 12,000 more in the queue. Happily, NV is four percentage points above its state RPS requirement of 20%.

Utilities and grid operators have no choice but to make sure the grid can handle all intermittent renewable and large-scale generation in the aggregate. One way this is done on a regional basis for California and neighboring states is through an “energy imbalance market,” a structure for 5-min and 15-min ancillary services to be procured by the grid and plant operators paid.

“NV Energy isn’t part of an ISO or an RTO but is a member of the energy imbalance market,” notes Murray.

Tracy’s transition. Murray illustrates what a “transition” can look like with NV Energy’s Frank A Tracy Generating Station 4/5, a 1 × 1 combined cycle unit. The “4” refers to the plant’s 6FA gas turbine/generator and the “5” to the 46-MW steam turbine/generator. Yes, you read that right. Tracy has the first of less than a handful of 6FA machines running in the North American 60-Hz market.

While it’s clear from Fig 1 how Tracy’s operating modes have changed over the last several years, what the chart does not show is that Unit 4/5 effectively became a marginal resource from management’s perspective. While this was caused by newer units coming online at Tracy, not by greater renewables penetration in the system, the transition experience can serve as a proxy for others facing marginal unit status.

“Beginning in 2009, Tracy 4/5 kept getting over-dispatched for several years,” Murray said. “The annual forecast showed 2000-3000 operating hours but it chronically operated in the 4000- to 5000-hr range. It was ‘out of the money’ for energy but necessary for reliability. Because the unit was so close to the margin, it was difficult to get a reliable forecast when it took only a few dollars of variation in market prices to drive it into profitability for ancillary services.”

The doughnut hole. “Northern Nevada [where Tracy is located], is a doughnut hole from the perspective of the regional grid,” Murray pointed out, “it’s somewhat isolated, and Tracy provided critical grid support in this timeframe, the only unit that could provide voltage support to a high-density load pocket of Reno-Sparks. In fact, Tracy 4/5 was often dispatched as a synchronous generator for reactive voltage support during periods of low load. As renewables penetration rose, Tracy’s critical position became even clearer.

The issue, it turns out, is that the operating-hours forecast was sensitive to the production model’s fuel price assumption. A nickel change could dramatically increase the spread in the operating-hour forecast range.

This uncertainty spilled over to the O&M plan for the unit. “When outages were conducted, Tracy 4/5 was scrutinized ever closer from a value-engineering perspective,” recalled Murray.

It’s pretty easy to see how a potential death spiral emerges. Low operating hours forecast, minimum dollars allocated for repair and upkeep, yet a rising number of starts and operating hours consistently higher than forecast.

Aggravating this is the small size of the 6FA fleet in the US, perhaps numbering in the single digits. Parts were quickly made obsolete, and NV Energy was self-managing maintenance (without long-term contracts). “Parts limitations under a deep cycling regime are a serious problem,” said Murray.

Contingency plans. The key to managing through this transition was to replace the O&M plan based on an average scenario with several plans having timelines which accommodate the sensitivity in the operating forecast. “Management needs as much flexibility as possible, and the goal is always to make it to the next outage at lowest possible cost. Nevertheless, some work/spending has to occur to cover uncertainties.”

Grid support Fig 2One way this is accomplished is Tracy 4/5 relies on non-OEM parts and repair. According to Murray, the LTSAs are most difficult to negotiate for a cycling unit that operates between a traditional peaker and baseload, because the critical components have the most design life expended. Units like Tracy 4/5 face a double whammy: Parts are obsolete and difficult to obtain, and design life evaporates faster. “It’s not easy to accommodate contingent pathways and arrive at an economical LTSA,” Murray stressed. This is evident from Fig 2.

Murray’s team had to get comfortable with non-OEM parts and repair, “though that has its challenges,” he conceded. Tracy 4/5 staff competitively bids parts and service for every outage. The relative risk has to be managed, as well as the marketing hype: Third-party providers often claim they can repair parts beyond their expected life cycle.

By contrast, OEMs tout “genuine” quality parts; but Tracy had two large “quality-driven” issues from parts supplied by the OEM. “In one case, said Murray, “we had S1B failures (close to liberation) during a third repair/replace cycle, after only 4000 hours into the maintenance cycle.”

He advises that others insist on a detailed quality control (QC) plan from the vendor and consider an independent QC as a hedge. Another consideration: The evaluation criteria for whether parts can withstand another repair cycle may be less stringent if the work scope is outside of an LTSA, as the vendor faces less risk.

Clearly, condition-based maintenance becomes paramount under “transition” circumstances. Tracy Station, in general, takes advantage of enhanced borescope inspections, parts life extension and upgrades, and optical scanning technologies. The facility also is a customer of NV Energy’s relatively new remote monitoring and diagnostic center, which, among other things, formalized a discovery and communication process with the plant. While Murray doesn’t point to the “big catch” that some M&D centers often tout to the industry, he acknowledges the NV Energy center’s contribution to evidence-based outage planning.

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